Substations in high and medium-voltage electric power networks include primary devices such as electrical cables, lines, bus bars, switches, power transformers and instrument transformers, which can be arranged in switch yards and/or bays. These primary devices are operated in an automated way via a Substation Automation (SA) system. The SA system includes secondary devices, so-called Intelligent Electronic Devices (IED), responsible for protection, control and monitoring of the primary devices. The IEDs may be assigned to hierarchical levels, i.e. the station level, the bay level, and the process level. The station level of the SA system includes an Operator Work Station (OWS) with a Human-Machine Interface (HMI) and a gateway to a Network Control Centre (NCC). IEDs on the bay level, also termed bay units, in turn are connected to each other as well as to the IEDs on the station level via an inter-bay or station bus primarily serving the purpose of exchanging commands and status information. IEDs on the process-level includes sensors, or instrument transformers, for voltage (VT), current (CT) and gas density measurements, contact probes for sensing switch and transformer tap changer positions, and/or intelligent actuators (I/O) for controlling switchgear like circuit breakers or disconnectors. Exemplary process-level IEDs such as non-conventional current or voltage transformers, or dedicated Merging Units (MU) assigned to conventional sensors, include an Analog to Digital (A/D) converter for sampling of analog signals. Process-level IEDs can be connected to the bay units via a process bus replacing a known hard-wired process interface.
A communication standard for communication between the secondary devices of a substation has been introduced by the International Electrotechnical Committee (IEC) as part of the standard IEC 61850 entitled “Communication Networks and Systems In Substations”. For non-time critical messages, IEC 61850-8-1 specifies the Manufacturing Message Specification (MMS, ISO/IEC 9506) protocol based on a reduced Open Systems Interconnection (OSI) protocol stack with the Transmission Control Protocol (TCP) and Internet Protocol (IP) in the transport and network layer, respectively, and Ethernet as physical media. For time-critical event-based messages, IEC 61850-8-1 specifies the Generic Object Oriented Substation Events (GOOSE) directly on the Ethernet link layer of the communication stack. For very fast periodically changing signals at the process level such as measured analogue voltages or currents IEC 61850-9-2 specifies the Sampled Measured Value (SMV) service, which, similar to GOOSE, builds directly on the Ethernet link layer. Hence, the standard defines a format to publish, as multicast messages on an industrial Ethernet, event-based messages and digitized measurement data from current or voltage sensors on the process level. SMV messages are transmitted over a process bus, which may, particularly in cost-effective medium or low voltage substations, extend to neighbouring bays, i.e. beyond the bay to which the sensor is assigned.
SA systems based on IEC 61850 are configured by means of a standardized configuration representation or formal system description called Substation Configuration Description (SCD) which is using a dedicated Substation Configuration Language (SCL). An SCD file contains the logical data flow between the IEDs on a “per data” base, for example, for every data sink/source, required/provided data sets are specified, from which a list of destination or receiver IEDs can be derived. Furthermore, the message size in terms of data set definitions, as well as the message sending rates for all periodic traffic like GOOSE and SMV is defined. The SCD file likewise specifies the distribution of multicast messages into Virtual Local Area Networks (VLANs) wherein a single IED may send different real time messages for different purposes within different VLANs of the SA communication system.
While IEC 61850 defines the way the SA devices can talk with each other, it does not define the communication architecture, for example, the way the devices are connected to each other. As one consequence of inter-operability, different architectures are nowadays technically feasible. FIG. 1 shows two examples of possible SA architecture for the same substation with two bays. The first example (top) is an architecture in which each bay includes a control IED C and two protection IEDs (e.g. main and backup) P1, P2. The second one (bottom) implements the backup protection functions for both bays onto one single IED P2 outside the bays.
The two above SA architectures may differ in a number of characteristic measures, such as performance, investment cost, maintenance cost, safety, security, and reliability. In this context, calculation of a reliability measure appears to be a highly subjective process and therefore needs to be clearly defined. Indeed, one may consider that the reliability of an SA system is the probability of having access to all, or all minus one, control devices from the station PC, while others will only consider the access to the merging units and breakers from the protection devices. Furthermore, analyzing a given complex architecture may require a reliability specialist, and/or involve a high probability of making mistakes during this process.
In this context, the principles and methods of the present disclosure are by no means restricted to a use in substation automation, but are likewise applicable to other process control systems with a standardized configuration description. In particular, it has to be noted that IEC 61850 is also an accepted standard for Hydro power plants, Wind power systems, and Distributed Energy Resources (DER) as well as for communications outside the substation (inter-substation communication for teleprotection, or substation-to-NCC communication).
The article by B. Yunus et al. entitled “Reliability and Availability Study On Substation Automation System Based on IEC 61850”, IEEE 2ND INTERNATIONAL POWER AND ENERGY CONFERENCE, 1.12.2008, discloses SA system reliability study based on a hierarchical structure involving a bay level includes hardwired IEDs, a station bus and a station level. The station optical fiber ring bus accounts for a lumped communication network reliability based on eight Ethernet switches. Otherwise, parallel and serial connections of components assigned to the different levels are considered for protection or control reliability. Communication path details are not considered.